This invention relates to distributed multiphase flow measurement systems to monitor multiphase flow production. More particularly the present invention incorporates sound speed measurements and/or bulk velocity measurements to fundamentally improve the ability of distributed multiphase flow measurement systems to monitor multiphase flow production.
It is widely recognized that the ability to measure the individual flow rates of oil/water/gas within co-flowing mixtures of these substances has substantial economic value for the oil and gas industry. The industry has been actively developing multiphase flow meters for the past 20 years. During this development process, many techniques have been identified, evaluated, refined, and commercialized.
The numerous approaches to multiphase flow measurement of the prior art can typically be divided into two main categories of multiphase flow meters (MPFM""s). The first category seeks to develop instruments to measure the oil/water/gas flow rates based on localized measurement. This is a typical industry approach in which a variety of measurements are made on the oil/gas/water mixture to help determine the flow rates of the individual components. This approach has focused on developing novel and robust instruments designed to provide precise multiphase flow measurements, such as dual-intensity gamma densitomers, microwave meters, capacitance and conductance meters, etc. Typically MPFM""s are a collection of several essentially separate, but collocated measurement devices that provide a sufficient number of measurements to uniquely determine the flow rate at the meter location. Prior art multiphase flow meter manufacturers for monitoring hydrocarbon production include Roxar, Framo, and Fluenta, among others. These MPFM""s are typically restricted to operate above the well, either on the surface or subsea, for various reasons including reliability in the harsh environment and complications due to the presence of electrical power. Since the MPFM""s typically operate at pressures and temperatures determined by production conditions and operators are typically interested in oil and gas production at standard conditions, the flow rates measured at the meter location are translated to standard conditions through fluid properties data (Pressure, Temperature, and Volumetric properties (PVT)).
The second category of prior art MPFM""s provides multiphase flow rate information by utilizing measurements distributed over the production system in conjunction with a mathematical description, or model, of the production system. The mathematical model utilizes multiphase flow models to relate the parameters sought to estimates for the measured parameters. The flow rates are determined by adjusting the multiphase flow rates to minimize the error between the distributed measurements and those predicted by the mathematical model. The type, number, and location of the measurements that enter into this global minimization process to determine flow rates can vary greatly, with cost, reliability and accuracy all entering into determining the optimal system.
Several prior art MPFM""s have been developed utilizing distributed measurements to estimate production flow rates. Owing to the availability and relatively low cost and reliability of conventional pressure and temperature measurements, these systems have typically tended to focus on utilizing only distributed pressure and temperature measurements to determine flow rates. Unfortunately, the physics linking sparse pressure and temperature measurements to flow rates is rather indirect and relies on estimates of several, often ill-defined flow system properties such as viscosity and wall surface roughness. Thus, although it is theoretically possible to determine flow rates from a limited number of pressure and temperature measurements, it is generally difficult for such systems to match the accuracy of a dedicated multiphase flow measurement system as described above.
The distributed measurement approaches are fundamentally rooted in the relationship between flow rates and pressure and temperature. Specifically, pressure drop in flow within a pipe is due primarily to viscous losses which are related to flow rate and hydrostatic head changes which are related to density of fluid and hence composition. Axial temperature gradients are primarily governed by the radial heat transfer from the flow within the production tubing into the formation as the flow is produced and is related to the heat capacity of the fluid and the flow rate. The pressure drop and temperature losses are used to predict flow rates. The fundamental problem with this approach is that the relationship between flow rate and either of these two parameters is highly uncertain and often must be calibrated or tuned on a case-by-case basis. For instance, it is known that it is extremely difficult to accurately predict pressure drop in multiphase flow.
It is also recognized that the accuracy of distributed measurement systems utilizing pressure and temperature measurements can be improved utilizing additional phase fraction measurements provided by prior art sensors such as density, dielectric, and sound wave measurements. These auxiliary phase fraction measurements and/or volumetric flow rate measurements are performed by auxiliary sensors that constrain the global optimization for specific variables at specific locations. In addition to enhancing the overall accuracy and robustness, the auxiliary sensors reduce the need for in-situ tuning of the optimization procedure required to produce accurate results.
What is needed is a robust and accurate sensor apparatus for providing temperature, pressure and other flow related parameters to multiphase flow models. It is further necessary to provide a sensor that can survive in harsh downhole environments.
Objects of the present invention include provision of a system to provide multiphase flow information for a fluid within a pipe.
According to the present invention, an apparatus is provided for measuring a flow rate of a multiphase fluid in a pipe comprising sensors or sensor systems distributed at axial locations along the pipe measuring pressure, temperature, speed of sound, and/or velocity of the fluid at a location along the pipe, and providing signals indicative of the pressure, the temperature, the speed of sound, and the velocity of the fluid. A multi-phase flow model responsive to the signals provides a signal indicative of the flow rate of the multi-phase fluid.
According further to the invention, the model comprises logic that calculates the flow rate of the multi-phase fluid. According still further, the sensor or sensor systems are fiber optic based. Still further, the sensors comprise at least one fiber optic Bragg grating based sensor.
The present invention further provides an apparatus for measuring a flow rate of a multiphase fluid in a pipe comprising a spatial array of at least two pressure and temperature sensors, disposed at different axial locations along the pipe, and each measuring a pressure and a temperature of the fluid within the pipe at a corresponding axial location. Each of the sensors provides a signal indicative of the pressure and temperature of the fluid within the pipe at the corresponding axial location. A multi-phase flow model responsive to the signals provides a signal indicative of the flow rate of the multi-phase fluid.
The present invention further provides an apparatus for measuring a flow rate of a multiphase fluid in a pipe comprising a spatial array of two sensors or sensor systems disposed at different axial locations along the pipe. The spatial array comprising the first sensor or sensor system measures a pressure and a temperature of the fluid within the pipe at a corresponding axial location and provides a signal indicative of the pressure and temperature of the fluid within the pipe at the axial location of the first sensor. The second sensor or sensor system measures a pressure, a temperature, a speed of sound, and/or a velocity of the fluid at a corresponding location along the pipe, and provides signals indicative of the pressure, the temperature, the speed of sound, and the velocity of the fluid at the axial location of the second sensor. A multi-phase flow model responsive to the signals provides a signal indicative of the flow rate of the multi-phase fluid.
The present invention further provides a method of measuring the flow rate of a multiphase fluid in a pipe. The method comprises measuring a pressure, a temperature, a speed of sound, and a velocity of the fluid at a location along the pipe,. and providing signals indicative of the pressure, the temperature, the speed of sound, and the velocity of the fluid. The flow rate of the multi-phase fluid is calculated based on the signals. Still further, the present invention provides a method wherein the measuring step comprises measuring a pressure, a temperature, a speed of sound, and a velocity of the fluid at a plurality of locations along the pipe.
The foregoing and other objects, features and advantages of the present invention will become more apparent in light of the following detailed description of exemplary embodiments thereof.